Method and system for downhole object location and orientation determination

ABSTRACT

A downhole device is provided that is intended to be co-located with an optical fiber cable to be found, for example by being fixed together in the same clamp. The device has an accelerometer or other suitable orientation determining means that is able to determine its positional orientation, with respect to gravity. A vibrator or other sounder is provided, that outputs the positional orientation information as a suitable encoded and modulated acoustic signal. A fiber optic distributed acoustic sensor deployed in the vicinity of the downhole device detects the acoustic signal and transmits it back to the surface, where it is demodulated and decoded to obtain the positional orientation information. Given that the device is co-located with the optical fiber the position of the fiber can then be inferred. As explained above, detecting the fiber position is important during perforation operations, so that the fiber is not inadvertently damaged.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 371 to PatentCooperation Treaty Application No. PCT/GB2015/051448, filed May 15,2015, which claims priority to U.S. Provisional Application No.61/994,474, filed May 16, 2014, the entire contents of which areincorporated herein by reference.

TECHNICAL FIELD

The present invention provides a method and system for determining theorientation and/or location of a downhole object, and in particular forexample an object such as an optical fiber cable that is located on theexterior surface of production tubing and held on by a clamp. Particularembodiments provide for a co-located device with the optical fiber thatis able to determine its own orientation and communicate the determinedorientation back to the surface.

BACKGROUND TO THE INVENTION AND PRIOR ART

To detect an acoustic signal downhole, distributed acoustic sensing(DAS) is commonly and effectively used. This method employs fibre opticcables to provide distributed acoustic sensing whereby the fibre opticcable acts as a string of discrete acoustic sensors, and anoptoelectronic device measures and processes the returning signal. Theoperation of such a device is described next.

A pulse of light is sent into the optical fibre, and a small amount oflight is naturally back scattered, along the length of the fibre byRayleigh, Brillouin and Raman scattering mechanisms. The scattered lightis captured by the fibre and carried back towards the source where thereturning signal is measured against time, allowing measurements in theamplitude, frequency and phase of the scattered light to be determined.If an acoustic wave is incident upon the cable, the glass structure ofthe optical fibre is caused to contract and expand within thevibro-acoustic field, consequently varying the optical path lengthsbetween the back scattered and/or reflected light scattered fromdifferent locations along the fibre The returning signal can beprocessed in order to measure the acoustical and/or vibrational field(s)at all points along the structure.

In known distributed acoustic sensing systems (DAS), standard fibreoptic cables are utilised to obtain a measurement profile from along theentire length of the fibre at intervals ranging from 1-10 meters.Further details regarding the operation of a suitable DAS system, suchas the iDAS™, available from Silixa Limited, of Elstree, UK are given inWO2010/0136809. Systems such as these are able to digitally recordacoustic fields at every interval location along an optical fibre atfrequencies up to 100 kHz. Since the location of the acoustic sensors isknown (the fibre deployment being known), the position of any acousticsignal can be thus identified by means of time-of-arrival calculations.

DAS systems find lots of applications in the oil and gas industry, andoptical fibers that can be connected to DAS systems, amongst otherthings, are often installed within wellbores, usually as a metal cablerunning parallel with the well bore casing clamped to the outsidethereof. In a typical oil or gas well, once the well bore has beendrilled and the casing installed, cement is used to fill the well boreexternal of the casing. However, as part of the “completion” process ofthe well, the casing and cement is perforated within the hydrocarbonbearing regions, to allow hydrocarbons to flow into the casing forextraction. Perforation is typically performed by a perforating gun,which is typically a cylindrical metal tube provided with shapedexplosive charges arranged around the circumference thereof. Theperforating gun is lowered through the casing to the intended productionzone, and the shaped charges are detonated, with the intention ofblasting holes through the casing and cement of the well, and into thesurrounding rock strata, to allow hydrocarbons to then flow through thecreated channels into the casing for extraction. Similarly, where afracturing fluid is to be pumped into the well to fracture the rockstrata, the created holes provide routes for the fracturing fluid toexit the well into the surrounding rock.

FIG. 11 illustrates the use of a perforating gun to generateperforations in a well bore casing and cement, and into the surroundingrock strata. Perforating gun 10 comprises a metal cylinder provided withshaped explosive charges arranged around the outer surface thereof. Forexample, the shaped charges may be provided in lines every 120 degreesaround the outer circumference of the gun. The gun is provided with acommunications line 12 to the surface for control purposes, to allow theexplosive charges to be detonated on command. In use as noted above thegun is lowered to the intended production zone, and the shaped chargesdetonated to blast through the casing and cement (as shown in FIG.11(b)), to create production channels in the surrounding rock stratathrough which oil or gas can flow to enter the well bore (as shown inFIG. 11 (c)).

One issue with the use of perforating guns is to try and prevent theshaped charges from damaging any control or sensing cabling or otherlines that may extend along the wellbore external of the casing. Forexample, optical fibers are commonly installed along the externalsurface of the casing within the wellbore, either for sensing purposesand/or for control of downhole tools. Care must be taken when using aperforating gun that the shaped charges are not pointed at the externalcabling or other lines such that the charges when detonated would seversuch lines. As the perforating is performed as part of the wellcompletion, by that point the fibers have typically already beencemented into the well bore, and hence repair can be very costly, oreven impossible. To try and prevent such damage occurring,conventionally the fibers and other signalling lines are located betweentwo metal rods or cables, and a magnetometer is provided on theperforating gun to try and detect the metal rods. That is, therotational orientation of the perforating gun is altered within thecasing whilst the magnetometer is used to detect the location of themetal rods either side of the fibers or other cabling. Once the metalrods have been detected, the orientation of the perforating gun can becontrolled to ensure that the shaped charges are pointed away from thearea of the metal rods, and hence the cabling or other lines to beprotected.

One problem with the above arrangement is one of cost, in that the metalrods are usually required to extend along a significant length of thewell bore, hence increasing the material and production cost of thewell. In addition, the use of magnetometers to detect the rods is notparticularly accurate, and particularly in some rock formations or insome regions where magnetic anomalies can occur that interfere with theoperation of the magnetometers. Moreover, the presence of the casing andother downhole equipment can interfere with the proper operation of themagnetometers, meaning that it is not reliably possible to rotationallyorient the perforating gun within the casing to ensure that the sensorand control lines and/or other cabling will not be damaged by the use ofthe perforating gun. In addition, the rods also form a potential leakagepath up the outside of the casing.

In order to address this problem WO2013/030555 describes a method andapparatus for determining the relative orientation of objects downhole,and especially to determining perforator orientation. The method,illustrated in FIG. 12, involves varying the orientation of an object,such as a perforator gun (302) in the wellbore and activating at leastone directional acoustic source (402 a-c). Each directional acousticsource is fixed in a predetermined location to the object and transmitsan acoustic signal preferentially in a known direction. The directionalacoustic source(s) is/are activated so as to generate sound in aplurality of different orientations of said object. An optical fiber(104) deployed down the wellbore is interrogated to provide distributedacoustic sensing in the vicinity of the object and the acoustic signalsdetected by the optical fiber are analyzed so as to determine theorientation of the at least one directional acoustic source relative tothe optical fiber, for instance by looking at the relative intensity inthe different orientations. Further details of the operation of thearrangement are described in the document, any and all of whichnecessary for understanding the present invention being incorporatedherein by reference.

Therefore, whilst the arrangement in WO2013/030555 apparently shouldovercome the cost and inaccuracy of the prior art magnetometerarrangements, the arrangement relies on the operation of a DAS system todetect the directional acoustic sources, with the directional acousticsources being described as conventional loudspeakers arranged to projectsounds forward and located in a casing that absorbs sound emitted inother directions. Conventional loudspeakers typically operate withinaudible frequency bands, for example in the range 20 Hz to 20 kHz, and atypical DAS of the prior art is usually capable of detecting sound atthese frequencies with good spatial resolution. However, thedirectionality of conventional loudspeakers, even provided in anotherwise insulating casing, is not high, and −3 dB directivity arcs of+/−50 to 60° can be common. FIG. 12 has been annotated to show typicalexample-directivity arcs for the three loudspeakers. As shown, suchdirectivity often means that even if the speaker is pointed away fromthe optical fibre, the fiber may still pick up a large signal from thespeaker. Allowing further for echoes and other multi-path effects withinthe casing, and the reliability of such a system begins to deteriorate.Basically, using conventional speakers as described in the prior artdoes not give a high enough directivity for the sound emitted toreliably determine the orientation of the perforating gun.

SUMMARY OF THE INVENTION

Embodiments of the invention provide a downhole device that is intendedto be co-located with an optical fiber, the location of which is to befound, for example by being fixed together in the same clamp. The devicehas an accelerometer or other suitable orientation determining meansthat is able to determine its positional orientation, with respect togravity. A vibrator or other sounder is provided, that outputs thepositional orientation information as a suitably encoded and modulatedacoustic signal. A fiber optic distributed acoustic sensor deployed inthe vicinity of the downhole device detects the acoustic signal andtransmits it back to the surface, where it is demodulated and decoded toobtain the positional orientation information. Given that the device isco-located with the optical fiber the position of the fiber can then beinferred. As explained above, detecting the fiber position is importantduring perforation operations, so that the fiber is not inadvertentlydamaged.

Other embodiments also provide the more general concept of having remotesensing devices deployed in an environment to be sensed and that senselocal conditions and/or stimuli with appropriate sensors, and that thenproduce modulated vibro-acoustic signals encoding the sensed localconditions and/or stimuli. The vibro-acoustic signals are then detectedby the optical fiber of an optical fiber distributed acoustic sensorsystem, the fiber being deployed into the environment to be sensed. Theincident vibro-acoustic signals on the fiber in turn modulatebackscatter and/or reflected optical signals that propagate back alongthe fiber, and which are then detected at a DAS processing box to whichthe fiber is connected to allow the vibro acoustic signals to be sensed.Subsequent demodulation and decoding of the sensed vibro-acousticsignals allows the local condition and/or stimuli information to then bere-obtained. In this way, the DAS system and its optical sensing fiberare being used as a return communications channel for sensor informationfrom the remote devices.

From one aspect there is provided an apparatus, comprising: i) anorientation detector arranged to detect the orientation of theapparatus; and ii) a vibrational or acoustic source arranged to producevibrational or acoustic signals in dependence on the detectedorientation of the apparatus, the produced vibrational or acousticsignals representing the detected orientation.

With such an arrangement an apparatus is provided that may be useddownhole to determine orientation of downhole elements, such as a clampfastening an optical fiber to production tubing.

In one embodiment the orientation detector is a relative bearing sensorbased on a magnetic encoder with eccentric weight sensitive to gravitywhen placed off the vertical plane. In some embodiments the relativebearing sensor detects the orientation of the apparatus with respect tothe direction of gravity.

In another embodiment the orientation detector is a three-axisaccelerometer that preferably detects the orientation of the apparatuswith respect to gravity.

In a further embodiment the orientation detector comprises one or moreoffset rotatably mounted magnetic masses, and a magnetic detectorarranged to detect the rotational orientation of the offset magneticmasses. Such an arrangement has advantages in terms of robustness andguaranteed operation.

In a yet further embodiment the orientation detector may be a relativebearing sensor.

In one embodiment the vibrational or acoustic source is arranged togenerate a modulated vibrational or acoustic signal that encodesinformation pertaining to the detected orientation. In this way,information can be transmitted vibro-acoustically from the downholedevice.

In one particular embodiment the vibrational or acoustic signal isfrequency modulated whereby to encode the information pertaining to thedetected orientation. In this respect, frequency modulated signals areeasier for a DAS detector to discriminate.

In one embodiment the frequency modulation comprises selection of one ora set of predetermined modulation frequencies corresponding torespective predetermined orientations. In particular, the set ofpredetermined modulation frequencies may be selected such that no memberof the set is a harmonic frequency of any other member of the set. Inthis way, discrimination between frequencies and accurate communicationof information is established.

In one embodiment the vibrational or acoustic source is an impulsesource that generates vibrational or acoustic impulses at one or morefrequencies corresponding to respective one or more detectedorientations. Again, such a signal is relatively easy for a DAS todetect and discriminate. In some such embodiments, the impulse source isan electro-mechanical tapper, such as for example, a solenoid drivendevice, or a piezo-electric driven device. As a consequence, tappingsignals of controllable frequency that are easy for the DAS to detectcan be generated.

In one embodiment the apparatus is provided within a sealed case withinwhich the orientation detector and the vibrational and/or acousticsource are contained. Such an arrangement helps to protect the apparatusfrom environmental conditions encountered downhole.

In one embodiment the apparatus further includes initiation circuitry,arranged to detect an external initiation condition that indicates thatthe orientation detector and vibrational and/or acoustic source shouldbegin to operate, the apparatus remaining quiescent until such conditionis detected. Thus feature helps to save battery life to those periodsuntil after actual installation of the device downhole and finalplacement of the production tubing, whilst maintaining the externalintegrity of the case.

In the above embodiment the external initiation condition is one or moreof: i) a magnetic field of at least a predefined activation value; ii)an electronic time delay of predetermined duration; iii) an accelerationor shock of at least a minimum predefined activation value; or iv) atemperature of at least a minimum predefined activation value; whereinthe predefined activation values are greater than typical ambientvalues.

Furthermore, in a two-way communication arrangement, the downhole devicecan also receive vibro-acoustic signals and so that it can be activatedand operated remotely. In this case the downhole device can be turnedon, send back the information and then go back to a standby conditionwith a low power requirement. This can extend the operating life of thedevice.

In one embodiment there is further provided a clamp for clamping opticalfiber to tubing or casing, the orientation detector and the vibrationaland/or acoustic source being co-located within the clamp with theoptical fiber.

Another aspect of the invention provides a distributed acoustic sensorsystem, comprising an optical fiber deployed along a well bore and asignal processing apparatus arranged to receive optical backscatterand/or reflections from along the optical fiber and to process suchbackscatter and/or reflections to determine vibrational and/or acousticsignals incident on the optical fiber, the optical fiber beingcollocated at one or more positions along the well bore with anapparatus according to the first aspect above, vibrational or acousticsignals from said apparatus being detected by said distributed acousticsensor system and processed to thereby determine the orientation of theapparatus.

A further aspect also provides a well or borehole arrangement,comprising production tubing having a plurality of clamps affixing oneor more optical fibers to the surface thereof, one or more of saidclamps containing an apparatus according to the first aspect above.

A still yet further aspect provides a system, comprising: i) a downholeor remote device, provided with at least one vibrational transducer andarranged to listen for vibro-acoustic or seismic signals pertaining tothe downhole or remote device, and to produce vibro-acoustic signalspertaining to the downhole or remote device; ii) a fiber opticdistributed acoustic sensor system, comprising an optical fiber deployeddownhole or into a sensing environment from a local position andarranged to listen for the vibro-acoustic signals produced by thedownhole or remote device; and iii) a transducer arranged to transmitvibro-acoustic or seismic signals into the ground or into the sensingenvironment; wherein the fiber optic distributed acoustic sensor systemcommunicates information from the downhole device to the surface bylistening for the vibro-acoustic signals produced by the downholedevice, and the transducer communicates information to the downhole orremote device. With such an arrangement a “closed-loop” communicationssystem is provided between the local position and the downhole or remotedevices, using the fiber optic DAS as the return channel to the surface.

In further embodiments, the downhole device may also be equipped withone or more further sensors, such as a pressure sensor, temperaturesensor, chemical sensor, or gravity, to measure properties of itssurroundings along the well bore or in the reservoir. The measurementsmay then be communicated by a suitably encoded vibro-acoustic signaloutput by a vibro-acoustic transducer on the device, such as a speakeror other sounder.

An array processing of the distributed acoustic data may be used toimprove the localisation of the device as well as improving thevibro-acoustic sensitivity.

The embodiment may also be applied for remote sensing and communicationsfor inland as well as for subsea. For example, as described furtherbelow, the optical fiber DAS may be used as a return communicationschannel for any remote sensing devices deployed within a sensingenvironment, which need not be a subterranean environment, but can beany environment into which an optical fiber can be deployed, and whichsupports the propagation of vibro-acoustic energy. Generally, the remotesensing devices sense local conditions and/or stimulil within theirlocal part of the sensing environment, and then generate avibro-acoustic signal encoding the sensed local conditions and/orstimuli. The vibro-acoustic signal is then detected by the optical fiberof the DAS, which communicates it back to the locality of the DASprocessor. As noted, therefore, the optical fiber DAS acts as acommunications channel to communicate sensor information from the remotedevices back out of the sensing environment.

In addition, a forward channel may also be provided, to allowcommunications with the remote devices. If the remote devices aredeployed underground, this forward channel might for example use aseismic transducer or other vibrational device to generate modulatedvibrations to be transmit through the ground to the devices. Where thedevices are above ground, appropriate radio channels may be used. Wherethe devices are subsea, acoustic based channels, such as sonar typechannels, may be used.

Further features and aspects of the invention will be apparent from theappended claims.

BRIEF DESCRIPTION OF DRAWINGS

Embodiments of the present invention, presented by way of example only,will now be described, with reference to the accompanying drawings,wherein like reference numerals refer to like parts, and wherein:

FIG. 1 is a diagram illustrating tubing having a fiber on the outsidethereof held in place by clamps;

FIG. 2 is a cross-section of part of FIG. 1;

FIG. 3 is a block diagram of the components of an apparatus according toan embodiment of the invention;

FIG. 4 is a cross section of a part of FIG. 1;

FIG. 5 is the cross section of FIGS. 2 and 4, annotated to showorientation detection;

FIG. 6 is a diagram illustrating the operation of an embodiment of theinvention;

FIG. 7 is an illustration of a clamp used in an embodiment of theinvention;

FIG. 8 is flow diagram of a first process used in an embodiment of theinvention;

FIG. 9 is flow diagram of a second process used in an embodiment of theinvention;

FIG. 10 is flow diagram of a third process used in an embodiment of theinvention;

FIGS. 11 and 12 are diagrams of aspects of the prior art;

FIG. 13 is a block diagram of components of an apparatus according to asecond embodiment of the invention;

FIG. 14 is a cross-section of the apparatus of FIG. 13;

FIG. 15 is an illustration of a clamp used in the second embodiment ofthe invention;

FIG. 16 is a flow diagram of a process used in the second embodiment ofthe invention;

FIG. 17 is diagram of a further embodiment of the invention;

FIG. 18 is a diagram of the internal components of the embodiment ofFIG. 17;

FIG. 19 is a diagram of a solenoid used in the embodiment of FIG. 17;

FIG. 20 is a diagram of some of the internal components of theembodiments of FIG. 17; and

FIG. 21 is a block diagram illustrating a further mode of operation ofembodiments of the invention.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

A brief overview of embodiments of the invention will first be given,followed by a detailed description of particular embodiments.

Fiber optic cables (FOC) installed on the outside of completion casingare at risk of being damaged during the perforation of the casing. Toavoid damaging the FOC the perforation charges are azimuthally orientedaway from the FOC. The azimuthal orientation of the FOC must bedetermined after installation of the FOC is complete. Traditionalmethods for determining the orientation of the FOC utilize instrumentsinside of the casing, typically conveyed on wireline, which detect thepresence of the FOC on the outside of the casing using electromagneticor ultrasonic measurements. To improve the reliability of detectionusing that method, wire rope, or other metallic mass, is installedparallel and adjacent to the FOC to increase the amount of metal mass tobe detected at a minimum length equal to the interval to be perforated.This method for determining the orientation of the FOC falls short ofthe required reliability and increases the risk of monetary loss andloss of control during the life of the well. To improve reliability andreduce risk we have conceived a downhole orientation tool (referred toherein as DOT) that will eliminated the need to install wire rope andeliminate the need for wireline runs to determine the orientation of theFOC.

The downhole orientation tool (DOT) measures its orientation relative togravity and transmits the orientation information through an acoustic ormechanical strain signal. The DOT can be installed with a known relativeposition to other downhole elements and can be used to infer theorientation of those elements. The downhole orientation tool utilizes aset of accelerometers (for example a three axis accelerometer) tomeasure the orientation of gravity relative to the tool. Theaccelerometer data is then transformed to an acoustic or mechanicalstrain signal using a mechanical or electromechanical device such as butnot limited to a solenoid, piezoelectric material, speaker, or vibrator.The acoustic signal is detected by the FOC which is connected to adistributed acoustic sensor (DAS) system. The acoustic signal measuredby the DAS system is read at the surface and transformed back into theaccelerometer data. The accelerometer data gives the orientation of theDOT relative to gravity.

The acoustic-mechanical signal generator can take many forms to optimizethe signal for detection by the fiber.

In one embodiment, the following steps are performed:

-   -   1. Accelerometer measures gravity    -   2. Microcontroller receive signal from accelerometer    -   3. Microcontroller converts signal to orientation and translates        orientation to an output signal sent to vibrator    -   4. Vibrator generates mechanical signal    -   5. DOT Vibrates at specific frequency or interval. The frequency        or interval is dependent on the orientation    -   6. Fiber optic control line is vibrated by vibrator    -   7. DAS surface interrogator measures vibration    -   8. Vibration translated back to orientation

In more detail, the DOT is a solution that knows the side of the pipe itis on using a sensor that is sensitive to gravity. Since the tool issensitive to gravity it will know if it is right-side-up or upside-downand all positions in-between. For example, if it is upside down then weknow it is on the bottom side of the casing. The tool will be installednext to the fiber such that a user can infer which side of the casingthe fiber is on from knowing which side of the casing the DOT is on.Then the user informs the driller which side of the casing the fiber ison at the interval to be perforated and they configure the perforationguns to orient the blasts away from the side of casing that the fiber ison.

Such a device will work in all situations apart from vertical wellsections, where there is no high side of the casing.

As mentioned, the tool will detect the angle of its reference siderelative to the high side of a deviated well. This measurement is thenconverted into a modulated acoustic signal that indicates the angularposition of the cable at each cable clamp relative to the high side ofthe borehole. The cable clamps are positioned at the tubing connections.

A DAS system (such as the Silixa® iDAS™) detects the individual signalsfrom each cable clamp position and dedicated software decodes and plotsthe measurement to indicate the relative bearing of the fibre opticcable at each clamp. The relative bearing would typically refer to theangle relative to the high side of the hole.

To summarize the intended use of the DOT devices, therefore:

-   -   1) During installation of an optical fibre cable the DOT device        will be co-located with the cable under each cable clamp along        the length of the production interval where planned or future        perforations may be introduced.    -   2) Once the production tubing is landed and is in its resting        orientation the devices will talk to the DAS with individual        cable orientations at each position.    -   3) The cable orientation will then be plotted versus depth with        a spatial resolution to match the spacing of the devices.        Expected to be at each cable clamp (˜40 feet).    -   4) The perforating company will then configure a passive        orientation string to be directed away from the cable at the        desired depth interval. This is done using eccentric weights        where gravity forces them to the low side of the hole.

Communication between the DOT device and the DAS can be coded to giveeach DOT device a unique code and it is possible this communicationcould be two-way i.e. a tool could be used to wake the DOT devices ortheir messages could be timed so that no intervention is needed oncethey are installed.

Should all else fail then the DOT devices would act as additional massesthat could be used in the prior art methods for locating a FOC downhole.

If the oriented downhole devices are powered (e.g. not necessarilysacrificial and battery operated, but instead all connected to a powersource) they may also be used for repeat perforating in the future andcould be used as a noise source in wells where the flow is quiet asdescribed in our prior unpublished co-pending International PatentApplication No. PCT/GB2013/052875, the entire contents of whichnecessary for understanding this aspect being incorporated herein byreference.

For example, a DOT device may also have batteries and charging circuitryto allow for that inductive charging. In this case a hybrid fiberoptic/electric cable may be installed in place of the fiber optic cable,which interacts with the charging circuitry to inductively charge thebatteries. Such an arrangement would be feasible for a large number ofwells, although may be less effective in high temperature downholeenvironments.

As mentioned, the DAS system may be a Silixa® iDAS™ system, the detailsof operation of which are available at the URLhttp://www.silixa.com/teclnology/idas/, and which is also described inour earlier patent application WO2010/0136809, any details of which thatare necessary for understanding the present invention being incorporatedherein by reference.

A more detailed embodiment of the invention will now be described withreference to FIGS. 1 to 10.

FIG. 1 illustrates an example section of well casing 10, having anoptical fiber 14 running along the exterior surface thereof. The opticalfiber 14 is held in place by a plurality of mechanical clamps 12 thatextend around the casing 10 to hold the fiber optic cable 14 against thecasing 10. The cable clamps may be separated from each other by up toseveral meters, for example they may be approximately 3 to 15 metersapart.

FIG. 2 is a section along the line A-A of FIG. 1, which illustrates theinternal contents of a clamp body 12. In particular, from FIG. 2 it canbe seen that a clamp 12, attached to the side of casing 10, containsfiber optical cable 14, as well as the downhole orientation tool device22, which is co-located next to the fiber optic cable 14 within theclamp body 12. By co-locating the downhole orientation tool 22 with thefiber optic cable, then any orientation that is determined for thedownhole orientation tool 22 should also substantially correspond to thefiber optical cable.

FIG. 4 reproduces FIG. 2, but shows an expanded section along the lineB-B, that is shown in FIG. 3. From FIG. 3 it can be seen that thedownhole orientation tool device 22 comprises an outer casing, withinwhich is contained a three axis accelerometer 32, which is arranged tocommunicate with a micro controller 34. The micro controller 34 receivessignals from the three axis accelerometer, and determines theorientation of the downhole orientation tool with respect to gravity, ina manner to be described. Having determined the orientation with respectto gravity, the micro controller 34 then controls a vibrator 36, tovibrate in a specific pattern in order to communicate the determinedorientation. That is, the vibrator 36 produces a modulatedvibro-acoustic signal that encodes the determined orientation, asdetermined by the micro controller. The components of the downholeorientation tool 22 are powered by a battery 38.

In use the downhole orientation tool 22 is co-located substantiallycontiguously with the fiber optic cable 14, for two reasons. The firstis such that the orientation that the downhole orientation tool is ableto determine for itself should also then substantially correspond to theorientation for the fiber optic cable, and hence the position of thefiber optic cable around the casing can then be inferred. Additionally,when the fiber optic cable is connected up to a distributed acousticsensor (DAS), the DAS system can then be used to detect thevibro-acoustic signal generated by the vibrator 36, which vibro-acousticfield is then detected by the DAS system via back scatter from along thefiber optic cable 14. The encoded and modulated orientation informationcan thus be obtained, and then subsequently demodulated and decoded togive the orientation information of the downhole orientation tool 22.

Of course, in some embodiments the downhole orientation tool 22 and thefiber optic cable 14 need not be actually touching, although thereshould be a good vibro-acoustically conductive connection therebetween.This can be achieved by mounting the fiber optic cable and the downholeorientation tool within the same rigid clamp structure.

FIGS. 5 and 6 illustrate the arrangements in operation. In FIG. 6 adistributed acoustic sensor box 62 is provided which is connected to thefiber optic cable 14, and receives back scatter signals fromthere-along, as known in the art. From the back scatter signals thedistributed acoustic sensor is able to determine the vibro-acousticfield at various resolutions along the fiber, typically from one metersto five meters resolution. The distributed acoustic sensor 62 is able tooutput its results via a screen 64.

FIG. 5 illustrates an example of the DOT in operation. Here the DOT 22is co-located with the fiber optic cable 14 within the clamp 12, and islocated at an angle of approximately 300 degrees from the verticalorientation, as measured clockwise. In this respect, the verticalorientation can be determined as being the opposite of the gravitationaldirection determined by the three axis accelerometer in the DOT 22.Therefore, briefly, the three axis accelerometer 32 determines the 300degree orientation, and passes this information to the micro controller34. The micro controller 34 encodes the orientation information (forexample, using ASCII encoding or the like) into a suitable controlsignal which is then used to modulate the output of the vibro-acousticvibrator 36. Various acoustic modulation schemes are known in the art,such as the well-known pulse width modulation schemes used to recorddata onto magnetic tapes. Alternatively, various frequency modulationschemes, such as, for example, DTMF related schemes may also be used.

The vibro-acoustic vibrations produced by the vibrator 36 are felt bythe fiber optic cable 14, causing back scatter from the section of cableadjacent to the downhole orientation tool 22, which back scatter canthen be detected by the distributed acoustic sensor box 62, themodulated acoustic signal from the vibrator 36 being determinedtherefrom. The modulated acoustic signal is then demodulated to retrievethe encoded orientation information. The encoded orientation informationmay then be decoded, and the decoded orientation information then outputon the screen 64, as shown.

FIG. 7 illustrates an example clamp 12, arranged around a section ofcasing 10, which has a fiber optic cable 14 running there-along. In thiscase the clamp 12 has two closing sections, and located underneath oneof these closing sections is the downhole orientation tool 22, attachedto the underside of one of the closing sections. When the closingsections are closed, the downhole orientation tool 22 is then broughtand held against the optical fiber 14. In this way, the clamp 12 holdsthe downhole orientation tool device 22 against or near to the fiberoptic cable 14, such that there is a good vibrational connectiontherebetween.

FIGS. 8, 9 and 10 illustrate the method of operation of the downholeorientation tool in more detail. With reference to FIG. 8, the stepsinvolved in installing the downhole orientation tool are explained.Firstly, at step 8.2 the downhole orientation tool device is co-locatedwith the fiber optic cable in a clamp, as described previously withrespect to FIG. 7. In this respect, the clamps 12 are fastened aroundthe production tubing with the fiber optic cable and the downholeorientation tool therein, as the production tubing is being fed into thewell. At step 8.4 the production tubing is installed into the well, andonce the production tubing is in place within the well, the orientationdevice is activated, at step 8.6. Alternatively, in one embodiment theorientation device 22 may be activated prior to being installed in theclamp, and operate constantly until its battery runs out. In thisrespect, the intended purpose of the downhole orientation tool in oneembodiment is to determine the orientation of the clamps 12, and henceany fiber held by the clamps, immediately after installation of theproduction tubing in the well. Once the production tubing is installedwithin the well, then usually it would not move much over time, andhence there is no need in some embodiments for the downhole orientationtool to continue to operate, once orientation measurements have beentaken.

Once the production tubing is installed within the well and the device22 has been activated, FIG. 10 shows the steps involved within thedevice 22 itself. That is, at step 10.2 with the device activated, theaccelerometer then switches on, and starts to send orientation signalswith respect to gravity to the micro controller, at step 10.4. At step10.6, the micro controller receives the signals from the accelerometer,and determines the downhole orientation tool's orientation with respectto gravity. As explained previously with respect to FIG. 5, the microcontroller receives the accelerometer signals, and then codes them intoa form suitable for transmission. This encoding may, for example,include packetisation of the accelerometer data into a data packet,including appropriate headers, and error correction coding. The encodedaccelerometer data is then used to modulate the output of the vibrator36 in accordance with a known acoustic modulation scheme, to produce amodulated acousto-vibrational signal that encodes the orientation of thedownhole orientation tool, at step 10.8. The resulting acousticvibrations from the vibrator 36 then travel to the fiber optic cable 14,via the clamp if necessary, where they are incident on the fiber opticcable, causing backscatter and/or reflected signals to occur from theincident section of fiber. The backscatter and/or reflected signals arethen detected by the attached DAS equipment 62.

At the DAS equipment 62, as shown at step 9.2, the orientationdevice-generated vibrational signals are received via the optic fiber 14at the DAS, and the DAS is then able to determine the incidentvibrational signals, which can then be demodulated and decoded to givethe device orientation. Once the device orientation is known, because itis also known that the device is substantially co-located with theoptical fiber 14, then the location of the optical fiber 14 around thecircumference of the casing 10 in the vicinity of the clamp can beinferred. By inferring the location of the optical fiber 14 in thismanner, when perforation of the casing is being performed using aperforating gun, the perforating gun may be controlled so as to avoidperforating the casing at the inferred position of the optical fiber 14.In this respect, here we assume that the cable is in a generallystraight path between each cable clamp and does not wrap completelyaround the tubing in the short distance between two clamps; this ensuresthat the typical spatial resolution (˜3-15 m) between the clamps isadequate to allow perforating between clamps without risk of damagingthe cables.

A second embodiment of the invention will now be described. Thisembodiment is related to the first embodiment, and many aspects thereofthat are identical are not described. Where the second embodimentdiffers is that instead of using an accelerometer and associatedmicrocontroller, a simpler rotational sensor, which may simply be aweighted rotational potentiometer or Hall effect sensor, is provided,together with an accompanying dedicated electronics processing pack(rather than a programmable microprocessor).

In more detail, in the second embodiment the downhole orientation toolutilizes a weighted rotational sensor to measure the orientation ofgravity relative to the tool. The sensor output is then transformed toan acoustic or mechanical strain signal using a mechanical orelectromechanical device such as but not limited to a solenoid,piezoelectric material, speaker, or vibrator. The acoustic signal isdetected by the FOC which is connected to a distributed acoustic sensor(DAS) system, as in the first embodiment. The acoustic signal measuredby the DAS system is read at the surface and transformed back into theaccelerometer data. The accelerometer data gives the orientation of theDOT relative to gravity.

The acoustic-mechanical signal generator can take many forms to optimizethe signal for detection by the fiber.

-   -   1. In the second embodiment, the following steps are therefore        performed:    -   2. rotational sensor settles with the weight downward as a        result of gravity    -   3. Rotational sensor position is measured using a hall-effect        sensor which outputs a voltage signal proportional to the angle.    -   4. The electronics pack converts the voltage signal to        orientation and translates orientation to an output signal sent        to vibrator    -   5. Vibrator generates mechanical signal    -   6. DOT Vibrates at specific frequency or interval. The frequency        or interval is dependent on the orientation    -   7. Fiber optic control line is vibrated by vibrator    -   8. DAS surface interrogator measures vibration    -   9. Vibration translated back to orientation

FIG. 14 is a section along the line A-A of FIG. 1, but applied to thesecond embodiment, and which illustrates the internal contents of aclamp body 12 according to the second embodiment. In particular, fromFIG. 14 it can be seen that a clamp 12, attached to the side of casing10, contains fiber optical cable 14, as well as the downhole orientationtool device 122, which is co-located next to the fiber optic cable 14within the clamp body 12. By co-locating the downhole orientation tool122 with the fiber optic cable, then any orientation that is determinedfor the downhole orientation tool 122 should also substantiallycorrespond to the fiber optical cable.

FIG. 13 shows a section along the line B-B of FIG. 14. Here it can beseen that the downhole orientation tool device 122 comprises an outercasing, within which is contained a relative bearing sensor 132, whichis arranged to communicate with an electronics package 134. Theelectronics package 134 receives signals from the relative bearingsensor, and determines the orientation of the downhole orientation toolwith respect to gravity, in a manner to be described. Having determinedthe orientation with respect to gravity, the electronics package 134then controls a vibrator 36, to vibrate in a specific pattern in orderto communicate the determined orientation. That is, the vibrator 36produces a modulated vibro-acoustic signal that encodes the determinedorientation, as determined by the electronics package. The components ofthe downhole orientation tool 122 are powered by a battery 38.

In operation the DOT 122 is co-located with the fiber optic cable 14within the clamp 12, as shown in FIG. 15, and for example may be locatedat an angle of approximately 300 degrees from the vertical orientation,as measured clockwise when looking downhole. In this respect, thevertical orientation can be determined as being the opposite of thegravitational direction determined by the three axis accelerometer inthe DOT 122. Therefore, briefly, the relative bearing sensor 132determines the 300 degree orientation, and passes this information tothe electronics package 134. The electronics package 134 encodes theorientation information (for example, using ASCII encoding or the like)into a suitable control signal which is then used to modulate the outputof the vibro-acoustic vibrator 36. Various acoustic modulation schemesare known in the art, such as the well-known pulse width modulationschemes used to record data onto magnetic tapes. Alternatively, variousfrequency modulation schemes, such as, for example, DTMF related schemesmay also be used.

The vibro-acoustic vibrations produced by the vibrator 36 are felt bythe fiber optic cable 14, causing back scatter from the section of cableadjacent to the downhole orientation tool 122, which back scatter canthen be detected by the distributed acoustic sensor box 62, themodulated acoustic signal from the vibrator 36 being determinedtherefrom. The modulated acoustic signal is then demodulated to retrievethe encoded orientation information. The encoded orientation informationmay then be decoded, and the decoded orientation information then outputon the screen 64, as shown.

FIG. 15 illustrates an example clamp 12, arranged around a section ofcasing 10, which has a fiber optic cable 14 running there-along. In thiscase the clamp 12 has two closing sections and a bridging section, andlocated underneath this bridging section is the downhole orientationtool 122, attached to the bridge. When the closing sections are closed,the downhole orientation tool 122 is then brought and held against theoptical fiber 14. In this way, the clamp 12 holds the downholeorientation tool device 122 against or near to the fiber optic cable 14,such that there is a good vibrational connection there between.

With respect to the operations of the second embodiment, as mentioned itis substantially the same as the first embodiment, and the processes ofFIGS. 8 and 9 described previously still apply. Inside the DOT of thesecond embodiment the process of FIG. 16 is followed, rather than thatof FIG. 10. This is described further below.

Once the production tubing is installed within the well and the device122 has been activated, FIG. 16 shows the steps involved within thedevice 122 itself. That is, at step 16.2 with the device activated, therelative bearing sensor then switches on, and starts to send orientationsignals with respect to gravity to the electronics package, at step16.4. At step 16.6, the electronics package receives the signals fromthe relative bearing sensor, and determines the downhole orientationtool's orientation with respect to gravity. As explained previously withrespect to FIG. 5, the electronics package receives the relative bearingsensor signals, and then codes them into a form suitable fortransmission. This encoding may, for example, include packetisation ofthe accelerometer data into a data packet, including appropriateheaders, and error correction coding. The encoded accelerometer data isthen used to modulate the output of the vibrator 36 in accordance with aknown acoustic modulation scheme, to produce a modulatedacousto-vibrational signal that encodes the orientation of the downholeorientation tool, at step 16.8. The resulting acoustic vibrations fromthe vibrator 36 then travel to the fiber optic cable 14, via the clampif necessary, where they are incident on the fiber optic cable, causingbackscatter and/or reflected signals to occur from the incident sectionof fiber. The backscatter and/or reflected signals are then detected bythe attached DAS equipment 62.

With the above second embodiment, therefore, the same advantages andeffects as the first embodiment can be obtained, but with slightly lowercost and simpler components. In particular, the replacement of theaccelerometer with a relative bearing device may increase robustness,and replacing a generally programmable microprocessor with a specific(and dedicated) electronics pack may reduce cost.

Various modifications may be made to the above described arrangements toprovide additional embodiments. Various such modifications are describedbelow.

In one further embodiment the on/off mechanism for the DOT could be athermostat which is set to power up the DOT on it reaching a certaintemperature, higher than ambient but lower than that downhole for thetarget well (for example, it could be set to 70 C). This would mean theDOT could be completely assembled, sealed and tested in itsmanufacturing location before shipping to the installation site. Onsite, there would be minimal scope for getting things wrong and no needto open the unit. Most importantly, it would draw no power until theunit reaches the set temperature.

As a variant to the above, the DOT may be actuated, or programmed tooperate by being exposed to a particular magnetic field, or by beingexposed to a certain level of acceleration or shock (e.g. hitting itwith a hammer etc.). The general concept is to provide an externalinitiation signal that causes the unit to start operating, withoutrequiring an external switch. By doing so the casing of the DOT canremain unitary and free of apertures, thus increasing its strength anddurability.

In one embodiment the DOT units may also be used for length referencingthe fibre length in the completion. This is because each DOT would be ata known position on the tubing string.

In other embodiments a DOT may also fulfil other measurement functions,for example it could measure temperature or pressure and send out thesevalues as an acoustic signal.

Moreover, in some embodiments a DOT may scavenge energy from thewellbore (for example vibrational energy) to allow it to take periodicmeasurements.

Furthermore, in some embodiments a DOT may output its value as a tone,the frequency of which encodes the value being transmitted. Analternative is to tap the orientation values out in a binary code,however, a tone is easier to produce, needs less energy and is easierfor a DAS to decode than a binary code. As mentioned previously,dual-tone multi-frequency (DTMF) tones may be used, where numbers are tobe communicated.

In another embodiment it is also possible to actuate and/or communicateto a downhole device by sending seismic messages or by tapping at thewellhead. In this respect, a downhole device such as the DOT device isalso provided with a microphone or other acoustic transducer with whichit is able to listen for vibrational or acoustic signals. With suchadditional provision a closed loop arrangement is possible where thedownhole device uses the optical fiber DAS system to communicate signalsback to the surface via its own local vibrational transducer, and thenthe surface is able to communicate back to the device via the seismicmessages and/or tapping at the well head (which is then transmittedalong the well tubing). With such an arrangement the DAS system mayconnect/collect data from one or more downhole wireless sensors.However, a 2-way communication can also be created which can be done byan acoustic or seismic source (212) at the surface, near the surface orsub-surface, with the DAS then being used to also confirm that thesignal has been communicated/received to the point of interest i.e. atthe downhole device.

FIG. 21 illustrates such an arrangement. As previously, here casing 10is provided with an optical fiber held in place by clamps 12. DAS system62 interrogates the optical fiber by sending optical pulses therealongand detecting the backscatter and/or reflections that come back from thepulses as they travel along the fiber. From the back scatter and/orreflections, which are modulated along the fiber by incidentvibro-acoustic energy, the acoustic field at each location along thefiber can be determined. Within FIG. 21 an acoustic or seismic source212 is provided at or near the surface, or under the surface, which isused to generate acoustic or seismic signals, the information content ofwhich can be modulated to convey desired control signals to the remoteDOT devices. Remote sensing devices (214), which may be in the same formas the DOT devices described herein, or may take other forms, but whichcan send data vibro-acoustically are further provided. Localisation ofsuch devices can be undertaken using array processing techniques, forexample based on the distributed acoustic data from the DAS system 62.Deployment of the remote sensing devices 214 can be undertaken by thembeing pumped or injected or deployed on the surface, subsurface and/orsubsea.

In addition, such a sensing arrangement need not necessarily be deployedonly in subterranean or downhole environments, but can be deployed moregenerally, such as on land, at sea, or subsea. For example, the opticalfiber of the distributed acoustic sensor system may be deployed into anyregion, area or volume in which sensing is to be undertaken. Remotesensing devices such as devices (212) can then be deployed throughoutthe region to sense the local conditions thereto and/or respond to localstimuli. Such local conditions and/or stimuli may include (but not belimited to) orientation of the device, local temperature at or near thedevice, local pressure at or near the device, local lighting conditionsat or near the device, local radio conditions at or near the device,local electromagnetic conditions, such as for example, magnetic field,at or near the device, local gravitational conditions at or near thedevice, local seismic conditions at or near the device, or any otherconditions or stimuli that might be measured, in any combinations.Whichever local conditions or stimuli are then measured or sensed by theremote devices, the remote devices then encode the sensed or measuredinformation as vibro-acoustic data, for example by appropriatemodulation of properties of an acoustic signal, and produce acousticvibrations to reproduce the vibro-acoustic data. The acoustic vibrationsare then detected by the optical fiber of the distributed acousticsensor system, resulting in the communication of the acoustic vibrationsback along the optical fiber (by way of modulated backscatter and/orreflections) to the processing box of the DAS system, where they aredecoded and interpreted to receive the information relating to the localconditions and/or stimuli around the respective remote devices 212.

Furthermore, although in most of the above embodiments we envisage theDOT devices to be battery powered, in other embodiments they could bepowered by a power wireline from the surface, Multiple DOTs could bepowered from a single power line, with appropriate power tap-offs.

A further embodiment of the invention will now be described with respectto FIGS. 17 to 20.

A further version of a DOT device according to a further embodiment ofthe invention is shown as cylindrical tube 172 in FIG. 17. In thisrespect cylindrical tube 172 is formed from stainless steel, and isprovided at both ends with respective caps 174, also made from stainlesssteel. The caps 174 are respectively laser welded all the way aroundtheir circumferences to secure them to the stainless tube with a fluidtight seal.

FIG. 18 shows the interior of the stainless steel tube 172. Here, thecomponents are arranged in a cylindrically stacked configuration so asto allow them to be fitted inside the stainless steel tube 172. As shownin FIG. 18, the DOT according to this embodiment comprises a solenoidhousing 182, within which is included a solenoid or otherelectromechanical actuator that is able to produce a mechanical movementin response to the application of an electrical signal. For example,other suitable actuators may be high temperature piezo-electricactuators, or the like.

In-line with the solenoid (or actuator) housing is a battery housing184, which in use contains one or more batteries, such as AA, or AAAbatteries, that are used to provide power to the device. Next in line(from left to right in FIG. 18) is a spinner housing, within which iscontained a rotatable and associated detection and control electronicsto detect rotational orientation of the spinner, and to control thesolenoid or other actuator accordingly. Further details of the spinnerhousing 186 will be described below with respect to FIG. 20. Finally,the arrangement is capped at both ends by respective caps 188 that actto secure the arrangement within tube 172, and to provide a fluid tightseal at each end with the interior surface of the tube 172.

FIG. 19 shows further details of the solenoid used as the actuator inone embodiment. The solenoid body is of standard construction as isknown in the art, having a metal plunger extending through the centre ofthe solenoid body. Inside the solenoid body are a plurality of turns ofwire, as is known in the art. The plunger is provided at one end with acap providing a shoulder for a spring that is arranged coaxially withthe plunger therearound, and which abuts against the shoulder and thesolenoid body to provide a spring return of the plunger to its restposition once it has been moved by the solenoid coil. The plungerextends through the entire body of the solenoid and extends out theother side via a plunger extension of reduced diameter that acts as atapper, for example to tap on the underside of cap 188 so as to produceimpulse like acoustic noises. As will be described later, the frequencyof such a tapping signal can be controlled in such a way as to conveyinformation relating to the orientation of the DOT device when it is inplace.

FIG. 20 illustrates the spinner housing 186 in more detail. Within thespinner housing 186 two printed circuit boards are provided, a first PCB204 having mounted thereon a thermal switch. The thermal switch is setto activate when the ambient temperature is increased to that of theintended operating environment i.e. downhole temperature. The thermalswitch controls the rest of the on-board electronics to activate at thatpoint.

The second PCB 206 has mounted thereon a microcontroller, arranged tointerface with a brass magnet holder 214 that forms part of a magneticsensor, arranged to detect the rotational position of two offsetmagnetic weights 212 mounted on a shaft. The weights 212 are arrangedoffset to the shaft such that shaft extends off-center through theweights, whereby the off-center weights rotate about the shaft in aneccentric manner. The shaft is held in place by a bearing 210, which isfixed in place with respect to the spinner housing by a bearing housing208, mounted on the spinner housing 186. In use the offset magneticweights rotate under gravity such that the greater part of their masshangs below the off-center shaft, and the rotational position of theweights is detected by the magnetic sensor 214, and fed to themicrocontroller. The microcontroller then controls the solenoid to tapat a certain rate in dependence on the rotational position of theweights. The rotational position of the weights about the shaft isindicative of the orientation of the DOT as a whole, as will bedescribed further below.

In further detail, the operation of the above described arrangement isas follows:

-   -   1) The DOT is installed downhole and allowed to settle into        position. Gravity direction is then detected by the magnetic        weights 212 mounted on the spindle with the mass of the weights        212 being off-axis. The magnetic sensor 214 detects the position        of the rotatable magnetic weights, as described above.    -   2) The DOT transmits a signal representing the detected angular        orientation as a pulsing of the solenoid 192. The angle is        encoded as the pulsing frequency.    -   3) The apparatus is sealed at manufacture (so that no        interaction is needed at the well site) and comes alive in the        following manner:        -   a. After being installed downhole the ambient temperature is            increased, and at the predetermined activation temperature            the electronics is activated using the thermal switch 204.            This means that the device draws no power until this            condition is met, allowing the device to be sealed at            manufacture many months before deployment.        -   b. After activation the device then draws minimal power            until no motion has been detected from the sensor for a            predetermined period (for example around 4 hours) which            should belong enough that the user knows the casing has            “landed” i.e. settled into position.        -   c. After this time period the solenoid turns on (i.e. only            then is significant power drawn), and the microprocessor            measures the rotational orientation of the offset weights,            to determine the angular orientation of the device.    -   4) In order to communicate the determined orientation of the        device, in this embodiment the solenoid 192 taps out a set        frequency to encode the detected angle in the range 0 deg to 360        deg. The set frequency will typically be in the range of 1 Hz to        5 Hz, taking into account the following:        -   a. The frequencies used should be selected to ensure that            pulsed frequencies are not multiples of one-another such            that harmonics cannot be confused with fundamental            frequencies. For example, 2 Hz should not be used if 1 Hz is            also being used. Instead, a slightly larger or smaller            frequency such as, for example, 2.1 Hz should be used. Set            out in table form below is a suitable selection of            frequencies for a 20 deg resolution using a frequency range            of 1.1 Hz to 4.7 Hz. Note, in this embodiment, the            frequencies are a set of quantised (digital) values rather            than continuous (analogue) values. This prevents the            harmonic issue described above, but in addition this            pre-knowledge of what the possible set of frequencies helps            to pick confidently the correct frequency/angle in the            signal detection/processing stage. For example, similar            processing to that used in a lock-in amplifier can be used            to better identify the actual frequency from the limited            number of possible frequencies.        -   b. Another (“out of band”) frequency is used (say 0.5 Hz)            for “no angle detected”—i.e. a fault        -   c. Another (“out of band”) frequency is used (say 0.7 Hz)            for another status update (for example, “I have reached            operating temperature, have stopped moving and am waiting            for the set time to be reached”)        -   d. A more complex pulse pattern may be sent periodically            (say once an hour) giving a unique device identification            code. This can be used to give additional clarification on            which device is located where.        -   e. The device may tap out continuously (or “dense            periodically”, such as 10 s every 1 minute) for around 12            hours and then less frequently over the next few days or            weeks (such as 10 s every hour for 2 days then 10 s every 6            hours thereafter). This mode is to allow a long period of            operation in the case the user misses the first “dense”            window of operation or if the user wish to confirm the            initial measurements.

The table below indicates example tapping frequencies for detectedorientation angle in one embodiment. Of course, in other embodimentsdifferent tapping frequencies may be used to encode different angles.

TABLE 1 Tapping frequencies for particular angular rotations Angle (°)Freq (Hz) 0 1.1 20 1.3 40 1.5 60 1.7 80 1.9 100 2.1 120 2.3 140 2.5 1602.7 180 2.9 200 3.1 220 3.3 240 3.5 260 3.7 280 3.9 300 4.1 320 4.3 3404.5

With the above arrangement, therefore, a robust downhole orientationdetermination device is provided that is temperature activated, andprovides information back to the surface by tapping at one or morepredetermined frequencies indicative of sensed orientation. As in theprevious embodiments, the tapping can be detected and measured by a DASsystem, to allow the orientation of the device to be found.

One constraint that can limit downhole operation are the high ambienttemperatures that may be experienced, and in particular the limit mostlikely being availability of high temperature batteries.

In order to address this issue, in some embodiments, non-chemical (i.e.not battery) energy storage mechanisms may be provided to power the DOT.For example, in one embodiment a wind-up micro generator may be providedthat starts unwinding at a set temperature. Alternatively, in anotherembodiment a compressed air powered generator may be provided, whichuses compressed air to power a micro-generator. In both cases, the timewe could power the sound source may be very limited, but provided thesignal is detected soon after actuation this is of little concern, asonce installed the position will not change. In addition, it should alsobe possible to provide a completely mechanical DOT, where a mechanicalmeans is used to decode detected orientation angle to tapping frequency,and to power the tapper. For example a balance wheel type clockworkpowered mechanism may be provided where the regulator lever on thebalance spring is linked to the offset weights such that rotation of theoffset weights adjusts the regulator lever so as to alter theoscillation of the balance wheel, and hence the resultant tappingfrequency generated via a tapping mechanism driven by the balance wheeloscillation.

In further embodiments, inductive charging of the DOT batteries may bepossible, for example where there is a hybrid electric/fiber optic cableand inductive charging circuitry is included, as discussed previously.

Various further modifications to the above described embodiments may bemade, whether by way of addition, deletion, or substitution, to providefurther embodiments, any and all of which are intended to be encompassedby the appended claims.

The invention claimed is:
 1. An apparatus, comprising: i) an orientationdetector arranged to detect the orientation of the apparatus; ii) avibrational or acoustic source arranged to produce vibrational oracoustic signals in dependence on the detected orientation of theapparatus, the produced vibrational or acoustic signals representing thedetected orientation, and iii) initiation circuitry arranged to detectan external initiation condition that indicates that the orientationdetector and vibrational and/or acoustic source should begin to operate,and to control the apparatus to begin operating, the apparatus remainingquiescent until such condition is detected, the initiation circuitrybeing further arranged to control the apparatus to go into a standbycondition after at least one orientation is detected.
 2. An apparatusaccording to claim 1, wherein the orientation detector is a three-axisaccelerometer that detects the orientation of the apparatus with respectto the direction of gravity.
 3. An apparatus according to claim 1,wherein the orientation detector comprises one or more offset rotatablymounted magnetic masses, and a magnetic detector arranged to detect therotational orientation of the offset magnetic masses.
 4. An apparatusaccording to claim 1, wherein the orientation detector is a relativebearing sensor.
 5. An apparatus according to claim 1, wherein thevibrational or acoustic source is arranged to generate a modulatedvibrational or acoustic signal that encodes information pertaining tothe detected orientation.
 6. An apparatus according to claim 5, whereinthe vibrational or acoustic signal is frequency modulated whereby toencode the information pertaining to the detected orientation.
 7. Anapparatus according to claim 6, wherein the frequency modulationcomprises selection of one or a set of predetermined modulationfrequencies corresponding to respective predetermined orientations. 8.An apparatus according to claim 7, wherein the set of predeterminedmodulation frequencies are selected such that no member of the set is aharmonic frequency of any other member of the set.
 9. An apparatusaccording to claim 1, wherein the vibrational or acoustic source is animpulse source that generates vibrational or acoustic impulses at one ormore frequencies corresponding to respective one or more detectedorientations.
 10. An apparatus according to claim 1, and furthercomprising a sealed case within which the orientation detector and thevibrational and/or acoustic source are contained.
 11. An apparatusaccording to claim 1, wherein the external initiation condition is oneor more of: i) a magnetic field of at least a predefined activationvalue; ii) an acceleration or shock of at least a minimum predefinedactivation value; iii) a temperature of at least a minimum predefinedactivation value; or iv) a duration of a predetermined time value;wherein the predefined activation values are greater than typicalambient values.
 12. An apparatus according to claim 1, and furthercomprising: i) a clamp for clamping optical fiber to tubing or casing,the orientation detector and the vibrational and/or acoustic sourcebeing co-located within the clamp with the optical fiber.
 13. Anapparatus according to claim 1, and further comprising control circuitryarranged to receive an orientation signal from the orientation detector,to determine the orientation of the device in dependence on theorientation signal, and to control the vibrational or acoustic source soas to produce vibrational or acoustic signals encoding the determinedorientation.
 14. A distributed acoustic sensor system, comprising anoptical fiber deployed along a well bore and a signal processingapparatus arranged to receive optical backscatter and/or reflectionsfrom along the optical fiber and to process such backscatter and/orreflections to determine vibrational and/or acoustic signals incident onthe optical fiber, the optical fiber being collocated at one or morepositions along the well bore with an apparatus according to claim 1,vibrational or acoustic signals from said apparatus being detected bysaid distributed acoustic sensor system and processed to therebydetermine the orientation of the apparatus.
 15. A well or boreholearrangement, comprising production tubing having a plurality of clampsaffixing one or more optical fibers to the surface thereof, one or moreof said clamps containing an apparatus according to claim
 1. 16. Anapparatus according to claim 1, wherein the external initiationcondition is not an external switch.
 17. An apparatus according to claim1, wherein the apparatus is unitary and free of apertures.